Systems and methods for evaluating reservoir supercharged conditions

ABSTRACT

Downhole formation pressure testing systems are provide. The systems include a drawdown pump, a probe configured to engage with a borehole wall and extract fluid from a formation, and a control element operably connected to the probe and the drawdown pump to perform a formation pressure testing operation. The formation pressure testing operation includes extracting a fluid from the formation for at least three drawdown intervals, monitoring a fluid pressure for a response interval at an end of each drawdown interval, measuring a fluid pressure at an end of each response interval to obtain a data point for each response interval, wherein each response interval is of the same duration, and wherein at least three data points are obtained, and performing a best fit analysis on the at least three data points, wherein the best fit analysis calculates a formation pressure.

BACKGROUND 1. Field of the Invention

The present invention generally relates to downhole tools and more particularly to systems and methods for measuring a formation pressure within supercharged conditions.

2. Description of the Related Art

Boreholes are drilled deep into the earth for many applications such as carbon dioxide sequestration, geothermal production, and hydrocarbon exploration and production. In all of the applications, the boreholes are drilled such that they pass through or allow access to a material (e.g., a gas or fluid) contained in a formation located below the earth's surface. Drilling and production operations may be dependent upon formation fluid pressures. However, during drilling operations, a portion of the drilling fluids may invade into the formation and thus generate supercharged conditions.

Supercharging exists when drilling fluid losses (dynamic and static) invade the near well-bore region in low permeability formations. Due to the overbalanced hydrostatic pressure (greater than formation pressure) the fluid invades but cannot be disbursed because of the low permeability of the formation (e.g., rock). This creates a near borehole region with pressures somewhere between hydrostatic and reservoir pressure. Measuring formation pressure in these conditions is difficult for formation testing tools which will normally record a pressure somewhere above true reservoir pressure but, due to the downhole conditions, the amount of increased pressure cannot be confirmed.

Accordingly, improved systems and methods for measuring a formation pressure in supercharged conditions may be beneficial.

SUMMARY

Disclosed herein are downhole formation pressure testing systems including a drawdown pump, a probe configured to engage with a borehole wall and extract fluid from a formation, and a control element operably connected to the probe and the drawdown pump to control the probe and the drawdown pump to perform a formation pressure testing operation. The formation pressure testing operation includes extracting a fluid from the formation for at least three drawdown intervals, monitoring a fluid pressure for a response interval at an end of each drawdown interval, measuring a fluid pressure at an end of each response interval to obtain a data point for each response interval to generate at least three data points, with a data point associated with each response interval, wherein each response interval is of the same duration, and performing a best fit analysis on the at least three data points, wherein the best fit analysis calculates a formation pressure.

Disclosed herein are methods for determining a formation pressure including disposing a downhole formation pressure testing system within a borehole, wherein the formation pressure testing system includes a drawdown pump and a probe configured to engage with a borehole wall and extract fluid from a formation, extracting a fluid from the formation for at least three drawdown intervals using the drawdown pump and the probe, monitoring the fluid pressure for a response interval at an end of each drawdown interval, measuring a fluid pressure at an end of each response interval to obtain a data point for each response interval to generate at least three data points, with a data point associated with each response interval, wherein each response interval is of the same duration, and performing a best fit analysis on the at least three data points, wherein the best fit analysis calculates a formation pressure.

BRIEF DESCRIPTION OF THE DRAWINGS

The subject matter, which is regarded as the invention, is particularly pointed out and distinctly claimed in the claims at the conclusion of the specification. The foregoing and other features and advantages of the invention are apparent from the following detailed description taken in conjunction with the accompanying drawings, wherein like elements are numbered alike, in which:

FIG. 1 is an example drilling system that can employ embodiments of the present disclosure;

FIG. 2 depicts a system for formation stimulation and hydrocarbon production that can incorporate embodiments of the present disclosure;

FIG. 3 is a schematic plot illustrating a drawdown and build-up pressure test process in accordance with an embodiment of the present disclosure;

FIG. 4 is a plot of data points obtained from a pressure test process in accordance with an embodiment of the present disclosure;

FIG. 5 is a plot of a best fit analysis to determine a formation pressure in accordance with an embodiment of the present disclosure;

FIG. 6 is a chi-squared (χ²) error versus pressure plot employed in some embodiments of the present disclosure to determine a formation pressure;

FIG. 7 is a schematic illustration of a formation pressure testing system in accordance with an embodiment of the present disclosure; and

FIG. 8 is a flow process for determining a formation pressure in accordance with an embodiment of the present disclosure.

DETAILED DESCRIPTION

FIG. 1 shows a schematic diagram of a drilling system 10 that includes a drill string 20 having a bottomhole assembly (BHA) 90, also referred to as a bottomhole assembly (BHA), conveyed in a borehole 26 penetrating an earth formation 60. The drilling system 10 includes a conventional derrick 11 erected on a floor 12 that supports a rotary table 14 that is rotated by a prime mover, such as an electric motor (not shown), at a desired rotational speed. The drill string 20 includes drill pipe 22 (e.g., a drilling tubular) extending downward from the rotary table 14 into the borehole 26. A disintegrating tool 50, such as a drill bit attached to the end of the BHA 90, disintegrates the geological formations when it is rotated to drill the borehole 26. The drill string 20 is coupled to a drawworks 30 via a kelly joint 21, swivel 28 and line 29 through a pulley 23. During the drilling operations, the drawworks 30 is operated to control the weight on bit, which affects the rate of penetration. The operation of the drawworks 30 is well known in the art and is thus not described in detail herein.

During drilling operations a suitable drilling fluid 31 (also referred to as the “mud”) from a source or mud pit 32 is circulated under pressure through the drill string 20 by a mud pump 34. The drilling fluid 31 passes into the drill string 20 via a desurger 36, fluid line 38 and the kelly joint 21. The drilling fluid 31 is discharged at the borehole bottom 51 through an opening in the disintegrating tool 50. The drilling fluid 31 circulates uphole through the annular space 27 between the drill string 20 and the borehole 26 and returns to the mud pit 32 via a return line 35. A sensor S1 in the line 38 provides information about the fluid flow rate. A surface torque sensor S2 and a sensor S3 associated with the drill string 20 respectively provide information about the torque and the rotational speed of the drill string. Additionally, one or more sensors (not shown) associated with line 29 are used to provide the hook load of the drill string 20 and about other desired parameters relating to the drilling of the borehole 26. The system may further include one or more downhole sensors 70 located on the drill string 20 and/or the BHA 90.

In some applications the disintegrating tool 50 is rotated by only rotating the drill pipe 22. However, in other applications, a drilling motor 55 (mud motor) disposed in the BHA 90 is used to rotate the disintegrating tool 50 and/or to superimpose or supplement the rotation of the drill string 20. In either case, the rate of penetration (ROP) of the disintegrating tool 50 into the borehole 26 for a given formation and a drilling assembly largely depends upon the weight on bit and the drill bit rotational speed. In one aspect of the embodiment of FIG. 1, the mud motor 55 is coupled to the disintegrating tool 50 via a drive shaft (not shown) disposed in a bearing assembly 57. The mud motor 55 rotates the disintegrating tool 50 when the drilling fluid 31 passes through the mud motor 55 under pressure. The bearing assembly 57 supports the radial and axial forces of the disintegrating tool 50, the downthrust of the drilling motor and the reactive upward loading from the applied weight on bit. Stabilizers 58 coupled to the bearing assembly 57 and other suitable locations act as centralizers for the lowermost portion of the mud motor assembly and other such suitable locations.

A surface control unit 40 receives signals from the downhole sensors 70 and devices via a sensor 43 placed in the fluid line 38 as well as from sensors S1, S2, S3, hook load sensors and any other sensors used in the system and processes such signals according to programmed instructions provided to the surface control unit 40. The surface control unit 40 displays desired drilling parameters and other information on a display/monitor 42 for use by an operator at the rig site to control the drilling operations. The surface control unit 40 contains a computer, memory for storing data, computer programs, models and algorithms accessible to a processor in the computer, a recorder, such as tape unit, memory unit, etc. for recording data and other peripherals. The surface control unit 40 also may include simulation models for use by the computer to processes data according to programmed instructions. The control unit responds to user commands entered through a suitable device, such as a keyboard. The control unit 40 is adapted to activate alarms 44 when certain unsafe or undesirable operating conditions occur.

The BHA 90 also contains other sensors and devices or tools for providing a variety of measurements relating to the formation surrounding the borehole and for drilling the borehole 26 along a desired path. Such devices may include a device for measuring the formation resistivity near and/or in front of the drill bit, a gamma ray device for measuring the formation gamma ray intensity and devices for determining the inclination, azimuth and position of the drill string. A formation resistivity tool 64, made according an embodiment described herein may be coupled at any suitable location, including above a lower kick-off subassembly 62, for estimating or determining the resistivity of the formation near or in front of the disintegrating tool 50 or at other suitable locations. An inclinometer 74 and a gamma ray device 76 may be suitably placed for respectively determining the inclination of the BHA and the formation gamma ray intensity. Any suitable inclinometer and gamma ray device may be utilized. In addition, an azimuth device (not shown), such as a magnetometer or a gyroscopic device, may be utilized to determine the drill string azimuth. Such devices are known in the art and therefore are not described in detail herein. In the above-described exemplary configuration, the mud motor 55 transfers power to the disintegrating tool 50 via a hollow shaft that also enables the drilling fluid to pass from the mud motor 55 to the disintegrating tool 50. In an alternative embodiment of the drill string 20, the mud motor 55 may be coupled below the resistivity measuring device 64 or at any other suitable place.

Still referring to FIG. 1, other logging-while-drilling (LWD) devices (generally denoted herein by numeral 77), such as devices for measuring formation porosity, permeability, density, rock properties, fluid properties, etc. may be placed at suitable locations in the BHA 90 for providing information useful for evaluating the subsurface formations along borehole 26. Such devices may include, but are not limited to, acoustic tools, nuclear tools, nuclear magnetic resonance tools and formation testing and sampling tools. In some embodiments of the presents disclosure, pressure testing tools and systems described herein may be part of the BHA 90, or other downhole systems and tools.

The above-noted devices transmit data to a downhole telemetry system 72, which in turn transmits the received data uphole to the surface control unit 40. The downhole telemetry system 72 also receives signals and data from the surface control unit 40 and transmits such received signals and data to the appropriate downhole devices. In one aspect, a mud pulse telemetry system may be used to communicate data between the downhole sensors 70 and devices and the surface equipment during drilling operations. A sensor 43 (e.g., a transducer) placed in the mud supply line 38 detects the mud pulses responsive to the data transmitted by the downhole telemetry 72. Sensor 43 generates electrical signals in response to the mud pressure variations and transmits such signals via a conductor 45 to the surface control unit 40. In other aspects, any other suitable telemetry system may be used for two-way data communication between the surface and the BHA 90, including but not limited to, an acoustic telemetry system, an electro-magnetic telemetry system, a wireless telemetry system that may utilize repeaters in the drill string or the borehole and a wired pipe. The wired pipe may be made up by joining drill pipe sections, wherein each pipe section includes a data communication link that runs along the pipe. The data connection between the pipe sections may be made by any suitable method, including but not limited to, hard electrical or optical connections, induction, capacitive or resonant coupling methods. In case a coiled-tubing is used as the drill pipe 22, the data communication link may be run along a side of the coiled-tubing.

The drilling system described thus far relates to those drilling systems that utilize a drill pipe to conveying the BHA 90 into the borehole 26, wherein the weight on bit is controlled from the surface, typically by controlling the operation of the drawworks. However, a large number of the current drilling systems, especially for drilling highly deviated and horizontal boreholes, utilize coiled-tubing for conveying the drilling assembly downhole. In such application a thruster is sometimes deployed in the drill string to provide the desired force on the drill bit. Also, when coiled-tubing is utilized, the tubing is not rotated by a rotary table but instead it is injected into the borehole by a suitable injector while the downhole motor, such as mud motor 55, rotates the disintegrating tool 50. For offshore drilling, an offshore rig or a vessel is used to support the drilling equipment, including the drill string.

Still referring to FIG. 1, a resistivity tool 64 may be provided that includes, for example, a plurality of antennas including, for example, transmitters 66 a or 66 b or and receivers 68 a or 68 b. Resistivity can be one formation property that is of interest in making drilling decisions. Those of skill in the art will appreciate that other formation property tools can be employed with or in place of the resistivity tool 64.

Turning now to FIG. 2, a schematic illustration of an embodiment of a system 200 for hydrocarbon production and/or evaluation of an earth formation 202 that can employ embodiments of the present disclosure is shown. The system 200 includes a borehole string 204 disposed within a borehole 206. The string 204, in one embodiment, includes a plurality of string segments or, in other embodiments, is a continuous conduit such as a coiled tube. As described herein, “string” refers to any structure or carrier suitable for lowering a tool or other component through a borehole or connecting a drill bit to the surface, and is not limited to the structure and configuration described herein. The term “carrier” as used herein means any device, device component, combination of devices, media, and/or member that may be used to convey, house, support, or otherwise facilitate the use of another device, device component, combination of devices, media, and/or member. Example, non-limiting carriers include, but are not limited to, casing pipes, wirelines, wireline sondes, slickline sondes, drop shots, downhole subs, bottomhole assemblies, and drill strings.

In one embodiment, the system 200 is configured as a hydraulic stimulation system. As described herein, “stimulation” may include any injection of a fluid into a formation. A fluid may be any flowable substance such as a liquid or a gas, or a flowable solid such as sand. In such embodiment, the string 204 includes a downhole assembly 208 that includes one or more tools or components to facilitate stimulation of the formation 202. For example, the string 204 includes a fluid assembly 210, such as a fracture or “frac” sleeve device or an electrical submersible pumping system, and a perforation assembly 212. Examples of the perforation assembly 212 include shaped charges, torches, projectiles, and other devices for perforating a borehole wall and/or casing. The string 204 may also include additional components, such as one or more isolation or packer subs 214.

One or more of the downhole assembly 208, the fracturing assembly 210, the perforation assembly 212, and/or the packer subs 214 may include suitable electronics or processors configured to communicate with a surface processing unit and/or control the respective tool or assembly. A surface system 216 can be provided to extract material (e.g., fluids) from the formation 202 or to inject fluids through the string 204 into the formation 202 for the purpose of fracing.

As shown, the surface system 216 includes a pumping device 218 in fluid communication with a tank 220. In some embodiments, the pumping device 218 can be used to extract fluid, such as hydrocarbons, from the formation 202, and store the extracted fluid in the tank 220. In some systems, as will be appreciated by those of skill in the art, the fluid may not be pumped to the surface, but may be captured in downhole pumps. In other embodiments, the pumping device 218 can be configured to inject fluid from the tank 220 into the string 204 to introduce fluid into the formation 202, for example, to stimulate and/or fracture the formation 202.

One or more flow rate and/or pressure sensors 222, as shown, are disposed in fluid communication with the pumping device 218 and the string 204 for measurement of fluid characteristics. The sensors 222 may be positioned at any suitable location, such as proximate to (e.g., at the discharge output) or within the pumping device 218, at or near a wellhead, or at any other location along the string 204 and/or within the borehole 206.

A processing and/or control unit 224 is disposed in operable communication with the sensors 222, the pumping device 218, and/or components of the downhole assembly 208. The processing and/or control unit 224 is configured to, for example, receive, store, and/or transmit data generated from the sensors 222 and/or the pumping device 218, and includes processing components configured to analyze data from the pumping device 218 and the sensors 222, provide alerts to the pumping device 218 or other control unit and/or control operational parameters, and/or communicate with and/or control components of the downhole assembly 208. The processing and/or control unit 224 includes any number of suitable components, such as processors, memory, communication devices and power sources.

As discussed above, drilling fluids (e.g., mud) will be pumped downhole to perform a drilling operation. At times, the fluids may seep into the formation around the borehole. Supercharging exists when drilling fluid losses (dynamic and static) invade the near well-bore region in low permeability formations. Due to the overbalanced hydrostatic pressure (greater than formation pressure) the fluid invades but cannot be disbursed because of the low permeability of the formation (e.g., rock). This creates a near borehole region with pressures somewhere between hydrostatic and reservoir pressure. Measuring formation pressure in these conditions is difficult for formation testing tools which will normally record a pressure somewhere above true reservoir pressure but, due to the downhole conditions, the amount of increased pressure cannot be confirmed.

One existing solution to this issue is to remove some of the supercharging fluid by performing large volume drawdowns. However, such drawdown operations can take significant time. One of the characteristic indications of supercharging is when successive pressure build-ups (after short drawdown periods) stabilize at lower pressures with each additional drawdown as more of the supercharging fluid is removed from the near well-bore region. Thus, typically, formation pressure may be estimated as a function of time, wherein reductions in the pressure, over time, will approach actual formation pressure.

Embodiments described herein are directed to reducing the time required to determine a formation pressure. For example, embodiments described herein are directed to methods for determining the reservoir pressure using formation pressure testing methods and analyzing the successive drop in build-up pressure as a function of volume or time equivalent (as opposed to the conventional method of pressure as a function of elapsed time).

Turning to FIG. 3, a schematic plot 300 illustrating a drawdown and build-up pressure test process is illustratively shown. On plot 300, the horizontal axis is time (in hours), the left vertical axis is pressure (in psi), and the right vertical axis is volume (in cc). At time zero, a drawdown process is initiated. The drawdown process may be performed using a system having various components disposed downhole, as will be appreciated by those of skill in the art. Data points 302 of FIG. 3 represent a volume of fluid removed from a formation and data points 304 represent a formation response (i.e., sensed pressure). As series of drawdown intervals 306 a-306 d are shown with respect to the fluid volume that is extracted from the formation. After each drawdown interval 306 a-306 d is a response interval 308 a-308 d during which a pressure response of the formation fluid is monitored.

As shown, a characteristic shape of pressure monitoring data in a supercharged formation is illustratively shown as ‘stair stepped’ down with each successive response interval 308 a-308 d (i.e., pressure build-up maximum is less within each successive response interval) reaching a slightly lower pressure than the previous build-up due to more super-charging fluid being removed from the formation during each successive drawdown interval 306 a-306 d.

In accordance with embodiments of the present disclosure, the build-up pressures (data obtained during the response intervals 308 a-308 d) can be plotted as a function of volume rather than time and still monitor a decay in pressure, as shown in FIG. 4. FIG. 4 is a schematic plot 400 illustrating pressure (y-axis) as a function of volume (x-axis).

Normal practice is to allow the build-up time to continue until the pressure is stabilized (even if the pressure is known to be above the reservoir pressure). That is, typically, a drawdown interval is performed, and the response interval is performed for as long as it takes for the pressure to stabilize. However, this type of drawdown and response operation takes a significant amount of time and the pressure may not ever stabilize to a standard criteria used in normal pressure testing.

Accordingly, embodiments, of the present disclosure are directed to plotting or recording the fluid pressure at a fixed time after the start of each build-up period. That is, as illustrative in FIG. 3, each drawdown interval 306 a-306 d and each response interval 308 a-308 d is a preset and uniform time period. Although illustratively shown in FIG. 3 with the drawdown intervals 306 a-306 d and the response intervals 308 a-308 d having the same length of time, such is not to be limiting. That is, the time intervals of the present disclosure are not required to be fixed, and may be longer or shorter than the example embodiment described herein (i.e., the time interval may vary). In embodiments of the present disclosure, each drawdown interval 306 a-306 d has the same length of time or duration, and each response interval 308 a-308 d has the same length of time or duration, but the durations of the drawdown intervals 306 a-306 d is not required to be the same as the duration for the response intervals 308 a-308 d. Such process allows the formation to respond for a fixed period of time and the pressure response is a function of the volume removed (i.e., the supercharging fluid removed from the near well-bore region), as illustratively shown in FIG. 4.

As illustrated in FIG. 4, the pressure can be recorded at different delta-time (i.e., time intervals) after build-up start (i.e., after the response interval begins) giving different decay curves 402, 404. The decay curve 402 is a data set with a 15 minute interval measurement duration and decay curve 404 is a data set with a 30 minute interval measurement duration. The decay in the pressure, as plotted in the decay curves 402, 404, indicates a trend toward the reservoir pressure and can be fitted to an exponential decay function of the form:

Y=Ae ^(−BX) +C   (1)

In equation (1), Y is formation pressure, X is one of a volume removed from the formation by the drawdown pump or a time equivalent of the volume removed, and A, B, and C are constants. Equation (1) is a best fit analysis equation for estimating or calculating a formation pressure.

In accordance with one example embodiment of the present disclosure, C can be set to “true reservoir pressure” and constants A and B may be adjusted to fit the measure decline. Constant A represents the magnitude of supercharging and constant B represents the decay and is depending on the formation mobility and near well-bore environment (e.g., a specific delta-T after start of build-up).

Turning now to FIG. 5, a schematic plot 500 of best fit curves of pressure as a function of volume, using equation (1), is shown. The decay curves 402, 404 of FIG. 4 (along with a decay curve 406 having a different fixed interval measurement duration) may be plotted and a number of best fit curves 502, 504, 506 based on equation (1). The best fit curves 502, 504, 506 may be matched to multiple decay curves (represented by multiple delta-T build-up periods) using the exponential decay function based on criteria described herein.

For example, in one non-limiting example, all constant C values for each best fit curve must be the same. The constant C is uniform for each best fit curve because each best fit curve is decaying toward the same reservoir pressure. The constant A values at volume zero (i.e., the start of the first drawdown interval) must be the same because each drawdown interval will start from the same initial supercharged pressure. Furthermore, the constant A values for each best fit curve must be greater than the highest pressure for the first response interval. Therefore, the B values of the best fit curves 502, 504, 506 can be adjusted to provide the best fit for each decay curve 402, 404, 406.

Because the true formation pressure is unknown (constant C) and is desired as an output, an iterative approach may be employed in some embodiments. Each decay equation may be optimized using the criteria mentioned above for a series of pressures that span the expected range of possible reservoir pressures. For each solution, a chi-squared (χ²) error may be obtained (i.e., a difference between a measured pressure and a computed pressure (based on equation (1)), squared) for each simulated pressure.

FIG. 6 is a plot 600 of the chi-squared (χ²) error versus pressure, with each data point representing a chi-squared (χ²) error for a given best fit curve based on equation (1). The minimum error indicates the best fit to the actual data and indicates the true reservoir pressure. That is, the minimum chi-squared (χ²) error 602 represents the best fit and lowest amount of error that occurs within the best fit curve. Accordingly, the best fit curve that is drawn from equation (1) represents the best fit constants A, B, and C, and thus the true reservoir pressure C may be obtained, as each of the other constants are uniform for each best fit curve for a given drawdown operation.

Turning now to FIG. 7, a schematic illustration of a formation pressure testing system 700 in accordance with an embodiment of the present disclosure is shown. The formation pressure testing system 700 is disposed downhole and may be arranged as part of a downhole tool 702 or may be otherwise part of a drill string or other component thereof (e.g., as part of a bottomhole assembly). In some embodiments, the formation pressure testing system 700 may be housed in a discrete housing and deployed on a wireline or may be a distinct or separate tool that is deployed downhole.

The formation pressure testing system 700 includes a drawdown pump 704, and one or more pressure gauges 706. The drawdown pump 704 is connected to a fluid line 708 which fluidly connects the drawdown pump 704 to a probe end 710. The probe end 710 is arranged at the end of a probe arm 712. In some embodiments, the probe end 710 is arranged with a sealing packer 714 that can provide sealing engagement or contact of the probe end 710 against a formation or borehole wall. Attached to the drawdown pump 704 is a sensor 716 that is, in some embodiments, arranged to detect movement and/or position of a piston 718 of the drawdown pump 704. The sensor 716 can monitor a volume of fluid that is extracted from a formation by the drawdown pump 704. The drawdown pump 704, in some embodiments, may be arranged to extract a small volume of fluid, e.g., between 2 and 50 cc, and in some embodiments may be between 5 and 10 cc of fluid.

As shown, the downhole tool 702 is positioned within a borehole 720. The borehole 720 is a drilled or formed hole within an earth formation, and may pass through one or more non-reservoir formations 722 and one or more reservoir formations 724. As shown, a mud cake 726 may form along a wall 728 of the borehole 720 at the location of the reservoir formation 724. A drilling fluid may invade into the reservoir formation 724 to form a supercharged reservoir formation 730. The above described process may be employed using the formation pressure testing system 700 by extracting some of the fluid within the supercharged reservoir formation 730 and monitoring fluid pressure as a function of time or volume.

In operation, the formation pressure testing system 700 will be deployed downhole and the probe arm 712 may be extended toward the wall 728 of the borehole 720. The probe end 710 and the sealing packer 714 will engage with the wall 728, with the sealing packer 714 ensuring that only fluids from within the supercharged reservoir formation 730 are extracted by the formation pressure testing system 700. That is, the sealing packer 714 can prevent fluids within the borehole 720 from being pulled into the formation pressure testing system 700. In some embodiments, one or more optional support arms 732 may be provided to aid in the engagement of the probe end 710 with the supercharged reservoir formation 730.

The formation pressure testing system 700 may further include a control element 734. The control element 734 can control aspects of the formation pressure testing system 700 and/or operation thereof. In some embodiments, the control element 734 includes one or more processors and one or more storage media elements (e.g., memory) to enable initiation of a pressure testing operation and data collection, and potentially data analysis. In some embodiments, the control element 734 includes a transceiver for transmitting data to the surface and/or receiving commands from the surface, as will be appreciated by those of skill in the art.

Turning now to FIG. 8, a flow process 800 for determining a reservoir formation fluid pressure in accordance with an embodiment of the present disclosure is shown. The flow process 800 may be performed using various components as shown and described above, and may implement the best fit analysis described above (whether performed downhole or at the surface).

At block 802, a formation pressure testing system is deployed downhole. The formation pressure testing system may be part of a drill string or bottomhole assembly of a drill string, or may be a separate component that is independently deployed downhole. In some embodiments, the deployment of the formation pressure testing system may be along with a drill string, and the remaining aspects of the flow process 800 may be performed during a stoppage of drilling (e.g., when the drill string is not rotating).

At block 804, a probe of the formation pressure testing system is deployed or operated to engage with a supercharged reservoir formation. The probe may include a probe end and sealing packer, as described above, to enable a fluid seal against a borehole wall.

At block 806, the probe and a fluidly connected drawdown pump maybe operated to extract a fluid from the supercharged formation. The extraction of the fluid may be performed for a drawdown interval. The drawdown interval may be a preset duration of time for extraction of fluid from the supercharged formation. In some embodiments, the drawdown interval may be on the order of, for example, 3 minutes, 5 minutes, 6 minutes, 10 minutes, 15 minutes, 30 minutes, 60 minutes (i.e., some embodiments may have time intervals that are at least 3 minutes).

At block 808, at the end of the drawdown interval, the fluid pressure within the formation pressure testing system may be monitored for a response interval. In some embodiments, the response interval may be on the order of, for example, 3 minutes, 5 minutes, 6 minutes, 10 minutes, 15 minutes, 30 minutes, 60 minutes (i.e., some embodiments may have time intervals that are at least 3 minutes). The duration of the response interval is not required to be the same as the drawdown interval.

At block 810, at the end of the response interval a fluid pressure is measured and recorded.

After the data point at block 810 is recorded, blocks 806-810 may be repeated to collect a number of data points. In some embodiments, when the first extraction and drawdown interval is started, a fluid pressure may be measured and set as the magnitude of supercharging and represents the formation pressure with no fluid extracted therefrom.

Once a sufficient number of data points is obtained (at least three), at block 812, a best fit analysis is performed to determine or estimate the formation pressure. The best fit analysis of block 812 is performed as described above, and may employ equation (1) as described above.

Advantageously, embodiments of the present disclosure provide improved systems and methods for estimating and determining formation pressures when supercharged formation pressures exist. Embodiments provided herein reduce testing times significantly by basing formation pressure as a function of volume rather than a function of time.

While embodiments described herein have been described with reference to specific figures, it will be understood that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the present disclosure. In addition, many modifications will be appreciated to adapt a particular instrument, situation, or material to the teachings of the present disclosure without departing from the scope thereof Therefore, it is intended that the disclosure not be limited to the particular embodiments disclosed, but that the present disclosure will include all embodiments falling within the scope of the appended claims or the following description of possible embodiments.

Embodiment 1: A downhole formation pressure testing system comprising: a drawdown pump; a probe configured to engage with a borehole wall and extract fluid from a formation; and a control element operably connected to the probe and the drawdown pump to control the probe and the drawdown pump to perform a formation pressure testing operation, wherein the formation pressure testing operation comprises: extracting a fluid from the formation for at least three drawdown intervals; monitoring a fluid pressure for a response interval at an end of each drawdown interval; measuring a fluid pressure at an end of each response interval to obtain a data point for each response interval, wherein each response interval is of the same duration, and wherein at least three data points are obtained; and performing a best fit analysis on the at least three data points, wherein the best fit analysis calculates a formation pressure.

Embodiment 2: The downhole formation pressure testing system of any of the above embodiments, wherein the drawdown pump, the probe, and the control element are located in a bottomhole assembly.

Embodiment 3: The downhole formation pressure testing system of any of the above embodiments, wherein the control element comprises a transceiver for transmitting data to a surface controller.

Embodiment 4: The downhole formation pressure testing system of any of the above embodiments, further comprising a sealing packer arranged with the probe to provide a sealing engagement between the probe and the borehole wall.

Embodiment 5: The downhole formation pressure testing system of any of the above embodiments, further comprising a fluid line fluidly connecting the drawdown pump to the probe.

Embodiment 6: The downhole formation pressure testing system of any of the above embodiments, further comprising a pressure sensor connected to the fluid line to monitor a fluid pressure within the fluid line.

Embodiment 7: The downhole formation pressure testing system of any of the above embodiments, wherein the drawdown pump includes a piston, the system further comprising a sensor configured to monitor at least one of a position and a movement of the piston.

Embodiment 8: The downhole formation pressure testing system of any of the above embodiments, further comprising a support arm, wherein the support arm is operable to engage with the borehole wall to ensure engagement of the probe with the borehole wall.

Embodiment 9: The downhole formation pressure testing system of any of the above embodiments, wherein the best fit analysis comprises a best fit equation: Y=Ae^(−BX) +C, wherein Y is a formation pressure, X is one of a volume removed from the formation by the drawdown pump or a time equivalent of the volume removed, and A, B, and C are constants, wherein terms of the best fit equation are set to best fit the at least three data points.

Embodiment 10: The downhole formation pressure testing system of any of the above embodiments, wherein constant A is magnitude of supercharging, constant B is a function of mobility and build-up period, and constant C is a true formation pressure.

Embodiment 11: The downhole formation pressure testing system of any of the above embodiments, further comprising determining a minimum chi-squared (χ²) error, wherein the minimum chi-squared (χ²) error represents a set of terms of the best fit equation representing a true formation pressure.

Embodiment 12: A method for determining a formation pressure comprising: disposing a downhole formation pressure testing system within a borehole, wherein the formation pressure testing system includes a drawdown pump and a probe configured to engage with a borehole wall and extract fluid from a formation; extracting a fluid from the formation for at least three drawdown intervals using the drawdown pump and the probe; monitoring the fluid pressure for a response interval at an end of each drawdown interval; measuring a fluid pressure at an end of each response interval to obtain a data point for each response interval, wherein each response interval is of the same duration, and wherein at least three data points are obtained; and performing a best fit analysis on the at least three data points, wherein the best fit analysis calculates a formation pressure.

Embodiment 13: The method of any of the above embodiments, wherein the best fit analysis comprises a best fit equation: Y=Ae^(−BX)+C, wherein Y is a formation pressure, X is one of a volume removed from the formation by the drawdown pump or a time equivalent of the volume removed, and A, B, and C are constants, wherein terms of the best fit equation are set to best fit the at least three data points.

Embodiment 14: The method of any of the above embodiments, wherein constant A is magnitude of supercharging, constant B is a function of mobility and build-up period, and constant C is a true formation pressure.

Embodiment 15: The method of any of the above embodiments, further comprising determining a minimum chi-squared (χ²) error, wherein the minimum chi-squared (χ²) error represents a set of terms of the best fit equation representing a true formation pressure.

Embodiment 16: The method of any of the above embodiments, wherein the response interval is at least 3 minutes.

Embodiment 17: The method of any of the above embodiments, wherein during each drawdown interval between 2 and 50 cc of fluid are extracted from the formation.

Embodiment 18: The method of any of the above embodiments, further comprising performing a drilling operation prior to extracting fluid from the formation.

Embodiment 19: The method of any of the above embodiments, further comprising transmitting the at least three data points to a surface unit for processing.

Embodiment 20: The method of any of the above embodiments, further comprising measuring a fluid pressure at a beginning of a first drawdown interval.

In support of the teachings herein, various analysis components may be used including a digital and/or an analog system. For example, controllers, computer processing systems, and/or geo-steering systems as provided herein and/or used with embodiments described herein may include digital and/or analog systems. The systems may have components such as processors, storage media, memory, inputs, outputs, communications links (e.g., wired, wireless, optical, or other), user interfaces, software programs, signal processors (e.g., digital or analog) and other such components (e.g., such as resistors, capacitors, inductors, and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a non-transitory computer readable medium, including memory (e.g., ROMs, RAMs), optical (e.g., CD-ROMs), or magnetic (e.g., disks, hard drives), or any other type that when executed causes a computer to implement the methods and/or processes described herein. These instructions may provide for equipment operation, control, data collection, analysis and other functions deemed relevant by a system designer, owner, user, or other such personnel, in addition to the functions described in this disclosure. Processed data, such as a result of an implemented method, may be transmitted as a signal via a processor output interface to a signal receiving device. The signal receiving device may be a display monitor or printer for presenting the result to a user. Alternatively or in addition, the signal receiving device may be memory or a storage medium. It will be appreciated that storing the result in memory or the storage medium may transform the memory or storage medium into a new state (i.e., containing the result) from a prior state (i.e., not containing the result). Further, in some embodiments, an alert signal may be transmitted from the processor to a user interface if the result exceeds a threshold value.

Furthermore, various other components may be included and called upon for providing for aspects of the teachings herein. For example, a sensor, transmitter, receiver, transceiver, antenna, controller, optical unit, electrical unit, and/or electromechanical unit may be included in support of the various aspects discussed herein or in support of other functions beyond this disclosure.

The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should further be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The modifier “about” or “substantially” used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity). For example, the phrase “substantially constant” is inclusive of minor deviations with respect to a fixed value or direction, as will be readily appreciated by those of skill in the art.

It will be recognized that the various components or technologies may provide certain necessary or beneficial functionality or features. Accordingly, these functions and features as may be needed in support of the appended claims and variations thereof, are recognized as being inherently included as a part of the teachings herein and a part of the present disclosure.

The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a borehole, and/or equipment in the borehole, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.

Accordingly, embodiments of the present disclosure are not to be seen as limited by the foregoing description, but are only limited by the scope of the appended claims. 

What is claimed is:
 1. A downhole formation pressure testing system comprising: a drawdown pump; a probe configured to engage with a borehole wall and extract fluid from a formation; and a control element operably connected to the probe and the drawdown pump to control the probe and the drawdown pump to perform a formation pressure testing operation, wherein the formation pressure testing operation comprises: extracting a fluid from the formation for at least three drawdown intervals; monitoring a fluid pressure for a response interval at an end of each drawdown interval; measuring a fluid pressure at an end of each response interval to obtain a data point for each response interval, wherein each response interval is of the same duration, and wherein at least three data points are obtained; and performing a best fit analysis on the at least three data points, wherein the best fit analysis calculates a formation pressure.
 2. The downhole formation pressure testing system of claim 1, wherein the drawdown pump, the probe, and the control element are located in a bottomhole assembly.
 3. The downhole formation pressure testing system of claim 2, wherein the control element comprises a transceiver for transmitting data to a surface controller.
 4. The downhole formation pressure testing system of claim 1, further comprising a sealing packer arranged with the probe to provide a sealing engagement between the probe and the borehole wall.
 5. The downhole formation pressure testing system of claim 1, further comprising a fluid line fluidly connecting the drawdown pump to the probe.
 6. The downhole formation pressure testing system of claim 5, further comprising a pressure sensor connected to the fluid line to monitor a fluid pressure within the fluid line.
 7. The downhole formation pressure testing system of claim 1, wherein the drawdown pump includes a piston, the system further comprising a sensor configured to monitor at least one of a position and a movement of the piston.
 8. The downhole formation pressure testing system of claim 1, further comprising a support arm, wherein the support arm is operable to engage with the borehole wall to ensure engagement of the probe with the borehole wall.
 9. The downhole formation pressure testing system of claim 1, wherein the best fit analysis comprises a best fit equation: Y=Ae^(−BX)+C, wherein Y is a formation pressure, X is one of a volume removed from the formation by the drawdown pump or a time equivalent of the volume removed, and A, B, and C are constants, wherein terms of the best fit equation are set to best fit the at least three data points.
 10. The downhole formation pressure testing system of claim 9, wherein constant A is magnitude of supercharging, constant B is a function of mobility and build-up period, and constant C is a true formation pressure.
 11. The downhole formation pressure testing system of claim 9, further comprising determining a minimum chi-squared (χ²) error, wherein the minimum chi-squared (χ²) error represents a set of terms of the best fit equation representing a true formation pressure.
 12. A method for determining a formation pressure comprising: disposing a downhole formation pressure testing system within a borehole, wherein the formation pressure testing system includes a drawdown pump and a probe configured to engage with a borehole wall and extract fluid from a formation; extracting a fluid from the formation for at least three drawdown intervals using the drawdown pump and the probe; monitoring the fluid pressure for a response interval at an end of each drawdown interval; measuring a fluid pressure at an end of each response interval to obtain a data point for each response interval, wherein each response interval is of the same duration, and wherein at least three data points are obtained; and performing a best fit analysis on the at least three data points, wherein the best fit analysis calculates a formation pressure.
 13. The method of claim 12, wherein the best fit analysis comprises a best fit equation: Y=Ae^(−BX)+C, wherein Y is a formation pressure, X is one of a volume removed from the formation by the drawdown pump or a time equivalent of the volume removed, and A, B, and C are constants, wherein terms of the best fit equation are set to best fit the at least three data points.
 14. The method of claim 13, wherein constant A is magnitude of supercharging, constant B is a function of mobility and build-up period, and constant C is a true formation pressure.
 15. The method of claim 13, further comprising determining a minimum chi-squared (χ²) error, wherein the minimum chi-squared (χ²) error represents a set of terms of the best fit equation representing a true formation pressure.
 16. The method of claim 12, wherein the response interval is at least 3 minutes.
 17. The method of claim 12, wherein during each drawdown interval between 2 and 50 cc of fluid are extracted from the formation.
 18. The method of claim 12, further comprising performing a drilling operation prior to extracting fluid from the formation.
 19. The method of claim 12, further comprising transmitting the at least three data points to a surface unit for processing.
 20. The method of claim 12, further comprising measuring a fluid pressure at a beginning of a first drawdown interval. 